Cementing Best Practice Jorge Sierra

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Int roduc tion T a bl e of Conte n ts Jo b P roc e dur e s E ngine e ring a nd Pla nning S que e z e Ceme n ting Pl ug Ce menting Contr a c tor Re quir e me nts

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Intr oduc tion Ta b le o f Conte n ts Jo b P roc e d ur e s En gin e e rin g a nd Pla nning S que e z e Ceme nt ing Pl ug Ce menting C o n tr act o r Re quir e me nts

Introduction

Purpose

The purpose of this document is to teach and promote a “Best Practices” phi-losophy throughout the Unocal Global Drilling Community. Unocal spends millions of dollars each year on cementing operations. Poor planning and operational execution not only can lead to cement failure but can result in the loss of hydrocarbon recovery from the wellbore.

This document is a guide for planning and executing cementing operations for worldwide operations. It is realized that, in some well situations, the preferred Best Practice may not achieve the best results. Every cement job should be designed for the wellbore characteristics and the cementing objectives desired.

Promoting Best Practices is an ongoing effort throughout Unocal drilling operations. Given the wide variety of cementing operations going on through-out the Unocal drilling world, it is hoped that a collective sharing of Best Practices will help all areas obtain competent and economical cement jobs. Visit the Casing, Liner Running and Cementing Network LiveLink site to view the network’s charter, goals, and members’ names and contact informa-tion. Access the Toolbox section for engineering tools, calculation work-sheets, and detailed job examples.

Visit the Engineering Network LiveLink site now by clicking on this text link.

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Introduction

Tips for Using This Document

This document is divided into seven main categories: • Table of Contents

• Introduction

• Engineering and Planning • Job Procedures

• Plug Cementing • Squeeze Cementing • Contractor Requirements

“Engineering and Planning” and “Job Procedures” cover all the basics involved in planning and executing a primary cementing job. “Plug Cement-ing” and “Squeeze Cementing,” as the names suggest, contain information specific to these techniques.“Contractor Requirements” provides information about contractors’ responsibilities in ensuring the job is carried out as

planned.

Reminders

In many of the sections, you will find white text in the blue column at the left of the page, topped with an orange bar. These comments are emphasized to indicate their importance in the success of the job.

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Table of Contents

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Engineering and Planning

The first step in Engineering and Planning for cementing is to identify the purpose of the cementing operation. Once the purpose is clearly defined, the wellbore conditions and casing design must be evaluated to determine the cement placement, hydrostatic constraints, and volumes. The cementing con-tractor must be involved in this stage, as detailed in the Concon-tractor Require-ments section of this document.

Primary cement job failures are predominately due to a breakdown in the “displacement process,” which leads to channeling of the cement through the drilling fluid.

Application of the following guidelines for mud removal, cement and spacer design, in conjunction with a cementing software program, will enhance the displacement process and improve the probability of successful primary cementing. Cementing software can be used to help determine the optimum displacement parameters and safe operating equivalent circulating densities (ECD).

Mud Removal

Mud removal is best achieved through proper drilling fluid conditioning, pipe rotation or reciprocation, pipe centralization, and the use of properly designed spacers and flushes.

Drilling Fluid Conditioning

The condition of the drilling fluid is one of the most important variables in achieving good displacement during a cement job. Regaining and maintaining good mobility is the key. An easily displaced drilling fluid will have low gel strengths and low fluid loss. Pockets of gelled fluid, which commonly exist following the drilling of a wellbore, make displacement difficult and must be broken apart.

Pipe Movement

Pipe rotation or reciprocation before and during cementing helps break up gelled, stationary pockets of drilling fluid and loosens cuttings trapped in the gelled drilling fluid. Pipe movement allows high displacement efficiency at lower pump rates because it helps to keep the drilling fluid flowing. If the pipe is poorly centralized, pipe movement can compensate by changing the flow path through the casing and allowing the slurry to circulate completely around the casing. The industry does not specify a minimum requirement for pipe movement, however it acknowledges that even a small amount of move-ment will enhance the displacemove-ment process.

The cementing contractor’s role begins with the Engi-neering and Planning stage, and his work will parallel that of the Drilling Engineer. For details, see the Con-tractor Requirements section.

The condition of the drilling fluid is one of the most important variables in achiev-ing good displace-ment during a cedisplace-ment job.

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Engineering and Planning

In some instances, pipe movement is not recommended. For example, when equivalent circulating density and fracture pressure are very similar, or shal-low gas or water influx is critical, moving the pipe can induce surge and swab pressures that could promote pipe sticking and surface casing-head pressure. The use of mechanical devices, such as some models of liner hangers, may also prevent casing movement. All of these factors must be considered when designing the displacement program.

Pipe Centralization

Drilling fluid displacement is best achieved when annular tolerances are approximately 1.5 to 2 in. Centralization of very small annuli is very difficult, and pipe movement and displacement rates may be severely restricted. Very large annuli may require extreme displacement rates to generate enough flow energy to remove the drilling fluid and cuttings.

Centralizing the casing by placing mechanical centralizers across the intervals to be isolated is critical for effectively displacing the drilling fluid and placing cement all around the casing. In poorly centralized casing, cement will bypass the drilling fluid by following the path of least resistance; as a result, the cement travels down the wide side of the annulus, leaving drilling fluid in the narrow side.

Good pipe standoff ensures uniform flow around the casing and helps equal-ize the force that the flowing spacer and cement exerts around the casing, increasing drilling fluid removal. In a deviated wellbore, standoff is even more critical to prevent a solids bed from accumulating on the low side of the annulus. The industry benchmark for standoff is approximately 70%, how-ever the preferred standoff for a given well should be developed from com-puter modeling and will vary with well conditions.

To improve centralization of the casing, adhere to the following guidelines: • Use cementing simulator runs to determine the standoff necessary to

achieve complete flow around the casing.

• Run a centralizer calculation program and reference well deviation sur-veys to determine the number of centralizers necessary to achieve the rec-ommended standoff and their ideal placement.

• For liner jobs, include centralizers in the lap area to aid in the displace-ment of cedisplace-ment all around the casing perimeter either in the primary cement job or subsequent squeeze job.

• For highly deviated wells in which cuttings beds are likely, place the cen-tralizer on the lower joints to hold the landing shoe off of the bottom of the wellbore. This design will allow cuttings to pass underneath and help eliminate any snowplowing effect.

Drilling fluid displace-ment is best achieved when annular toler-ances are approxi-mately 1.5 to 2 in.

The industry bench-mark for standoff is approximately 70%.

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Engineering and Planning

Spacers and Flushes

Spacers and flushes are effective displacement aids because they separate unlike fluids such as cement and drilling fluid, and enhance the removal of gelled drilling fluid, allowing a better cement bond. Spacers can be designed to serve various needs. For example, weighted spacers can help with well control, and reactive spacers can provide increased drilling fluid-removal benefits. Compatibility of the drilling fluid/spacer as well as the compatibility of the spacer/cement slurry is of prime importance. Application of the com-patibility procedures as outlined in the API SPEC RP10B, 22nd Edition, December 1997 is highly recommended.

Parameters governing a spacer’s effectiveness include flow rate, contact time, and fluid properties. To achieve maximum drilling fluid displacement, adhere to the following guidelines:

Density

Set spacer density 0.5 to 1.0 ppg above the drilling fluid weight and at least 0.5 ppg less than the cement slurry density. In situations that require the dif-ference between cement weight and drilling fluid weight to be less than 1.0 ppg, design the spacer density to be mid-way between the two densities. Contact Time

Provide a contact time and volume of spacer that will provide optimum amount of drilling fluid removal. Typically 8 to 10 minutes contact time or 1,000 feet of annular space are adequate.

Rheology

Design spacer rheology that will provide turbulent flow where hole geometry allows. Turbulent flow of spacer is required on all liner jobs.

Compatibility

Spacer must be fully compatible with drilling fluid and cement. Contact with drilling fluid must not result in flocculation, settling, or excessive rheology. Contact with cement must not decrease pump time.

Stability

Spacer must remain stable with no excessive settling or separation. For all liner and tieback jobs, the spacer must be tested by “hot-rolling” at circulating temperature.

Wettability

When an oil-based or synthetic-based drilling fluid is in the hole, the spacer must also be capable of converting the pipe and hole to a “water wet” condi-tion. Compatibility of the drilling fluid/spacer as well as the compatibility of the spacer/cement slurry is of prime importance. Provide a contact time and volume of spacer that will pro-vide optimum amount of drilling fluid removal.

Spacer must be fully compatible with drilling fluid and cement.

For all liner and tie-back jobs, the spacer must be tested by “hot-rolling” at circu-lating temperature.

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Engineering and Planning

Operational Priorities

Determining how the cement will be placed in the hole is as important as the design of the cement itself. This section discusses the operational factors that should be determined in planning a successful job.

Job Volume Excess

Unless caliper data is available or excess volume is otherwise specified, use the recommended percentages in the following table to calculate cement slurry volume requirements across an open hole.

For cementing operations on offshore wells that use subsea housing, try to plan the well’s programs so that cement returns are not transported through the subsea housing. In such cases, the surface casing is usually cemented only to 500 ft above the conductor shoe. The presence of cement in the recesses of subsea housing can cause great difficulty in setting subsequent hangers or packoffs.

Flow Rate

Cement flow is characterized by three flow rate regimes: turbulent flow, lam-inar flow, and plug flow. High-energy displacement rates are most effective in ensuring good displacement. Turbulent flow conditions are desirable, but are not required. When turbulent flow is not a viable option for a formation, use the highest pump rate that is feasible for the wellbore conditions. The best results are obtained when the spacer and/or cement is pumped at maximum energy, the spacer or flush is appropriately designed to remove the drilling fluid, and a good competent cement is used.

To maximize displacement, adhere to the following guidelines:

• Design spacer to be in turbulent flow as it rounds the shoe and passes the sections to be isolated.

• Mix and pump cement as fast as density control, pumping equipment, material supply, and wellbore conditions allow.

Calculations of Volume Excess

Depth (ft) % Excess with Water-Based Mud % Excess with Oil-Based Mud 0 to 4,000 100 50 4,000 to 8,000 75 25 8,000 to 10,000 50 15 10,000 to 18,000 35 15 Greater than 18,000 25 15 High-energy displace-ment rates are most effective in ensuring good displacement.

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Engineering and Planning

• Displace at high rates (8 bbl/min and higher) without exceeding the for-mation breakdown pressure.

Downhole Equipment

Choose all downhole equipment (float collars, shoes, guide shoes, centraliz-ers, liner hanger systems, and wiper plugs) for fit, operation, and proper installation.

Centralizers

• Determine which type of centralizer is best for a particular application by evaluating the centralizer’s suitability for the specific application, its abil-ity to mitigate exposure for problems in the running of casing due to its design, and to provide centralization cost-effectively.

• Select appropriate centralizer types, stop rings, and casing connections to minimize the risk of centralizers sliding and stacking-out.

Bowspring-type centralizers provide an acceptable balance between cost and standoff for most standard cementing operations.

• If centralizers are at risk of becoming smashed when running through existing liner tops or downhole components such as wellhead housings, choose a durable centralizer such as solid integral centralizer subs that can withstand these conditions.

• For highly deviated wellbores, evaluate the use of double bowspring or solid body centralizers to centralize the casing and to maintain or improve running force requirements. Tight clearances and holes drilled with bi-center bits may require the use of bow spring centralizer subs.

Wiper Plugs

Top and bottom cement plugs are recommended for every primary cementing job, when possible. The bottom plug minimizes contamination of the cement as it is pumped. The top plug prevents contamination of the cement slurry by the displacement fluid and provides a positive indication that the cement has been displaced. Use composite body plugs that are easy to drill out with PDC bits.

Choose all downhole equipment for fit, operation, and proper installation.

Bowspring-type centralizers provide an acceptable balance between cost and standoff for most standard cementing operations.

Top and bottom cement plugs are rec-ommended for every primary cementing job, when possible.

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Engineering and Planning

Shoe Joint

A shoe joint is recommended for all primary casing/liner jobs. The length of the shoe joint will vary. The absolute minimum length is one joint of pipe. If a bottom plug is not required, a minimum of two joints are required.

Considerations for Liner Jobs

A liner hanger must be designed for the combined loading of the liner weight to be hung off and the mud weight differential on the slip area to avoid exceeding the elastic limit on the ID of the casing in which the slips are engaged.

• Ensure that the liner hanger set pressures are well above the circulation pressures that could be required while running the liner to prevent prema-ture setting of the liner hanger.

• On all liner float shoes, verify that holes exist on the side of the float shoe, allowing circulation and preventing a hydraulic lockup in the event that the liner hanger fails and the liner lands on the bottom of the hole. • Use or design autofill float equipment that can be activated without

set-ting the liner hanger, should a well control condition arise while going in hole.

• Design liner hanger systems with a tieback sleeve length that allows the bottom of the tieback stem to be partially stung into the tieback sleeve when cementing the tieback casing. This will enhance the process of slacking off the tieback casing after the cement job has been completed. Buckling of the lower portion of the tieback casing after cementing can make it difficult to stab the tieback stem into place.

• For ultradeep liners on directional wells with relatively high torque and drag, use a pressure-indicating method to verify that a liner is released from the running tool. The actual liner weight may be small in compari-son to the drag forces, making it difficult to determine if the liner is actu-ally released.

Recommended Shoe Joint Lengths

Casing Size (in.) No. of Pipe Joints > 18 5/8 Tag in > 13 3/8 2 joints

> 9 5/8 3 joints > 7 5/8 6 joints

A shoe joint is recommended for all primary casing/liner jobs.

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Engineering and Planning

Cement Design Priorities

A slurry design must address a broad assortment of well conditions and well-control parameters. To maximize the performance of a slurry, adhere to these seven guidelines, listed in the order of importance:

Priority No. 1—Density

Cement slurry density must be within range to maintain well control. If hole conditions allow, cement slurry density should be a minimum of 1.0 ppg greater than drilling fluid weight and 0.5 ppg greater than the spacer weight.

Priority No. 2—Pump Time (Thickening Time)

The pump time should include the estimated job time plus a safety factor. The safety factor must be based on wellbore parameters, operational objectives and limitations, and the accuracy of expected temperatures to which the cement slurry will be exposed during the cementing process as compared to the laboratory testing conditions.

Keep the following in mind when specifying and evaluating thickening time: • The first sack or leading edge of the cement is exposed to different

tem-perature conditions and will require a different placement time than the last sack of cement.

• Consider the total placement time for the lead slurry (mixing and pumping of lead + mixing and pumping of tail + displacement).

Recommended Safety Factors

• For surface and intermediate strings where cement placement is relatively easy and minimal WOC is the objective, allow a 1-hr safety factor. • For HPHT liner cementing where cement placement is critical, allow a

minimum safety factor of 2 hours or 50% of the calculated job time, whichever is greater.

Priority No. 3—Mixability

Cement must be easy to mix at the cementing unit in order to achieve density control at a mixing rate that allows cement slurry placement within the avail-able pump time.

Priority No. 4—Rheology

The cement slurry must be pumpable, and the cement slurry rheological prop-erties must allow effective placement, with a PV and YP as low as possible, but higher than that of spacer or drilling fluid.

Cement slurry density must be within range to maintain well control.

The pump time should include the estimated job time plus a safety factor.

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Engineering and Planning

Priority No. 5—Fluid Loss Control

Design fluid loss control to specification. Excessive loss of fluid from the cement slurry has negative impact on other slurry properties.

Priority No. 6—Compressive Strength

The goal is to achieve rapid compressive strength development after place-ment. The minimum requirement is a WOC time (time to achieve 500 psi) of less than 12 hours and 24-hr strength greater than 1,000 psi.

Priority No. 7—Free Fluid and Settling

Cement slurry must remain stable (free water within specification and no sig-nificant settling or separation) while fluid. Design and test for given hole con-ditions, i.e. for directional well test at appropriate angle.

Cement Slurry Specifications

Slurry Properties Conductor and Surface Casings Intermediate Casings and Drilling Liners Production Casings and Liners Deep Production Liners and for

Gas Control Density + 1 ppg > drilling fluid density

< Equivalent Circulating Density (ECD) to fracture formation Thickening

Time

Job time plus at least one hour for safety factor For production casings or for gas control, the TT chart should display a right angle set (transition from 40 to 100 Bc in less than 15 minutes) Free Water < 1.0% < 0.5 % 0 % 0 % Fluid Loss NA < 250 < 100 < 50 Rheol. (PV) < 150 < 150 < 100 < 100 Rheol. (YP) < 50 < 40 < 25 < 20 Comp. Strength WOC (hr to 500 psi) < 12 < 8 < 8 < 8 24-hr Comp. Strength (psi) 1,000 2,000 2,000 2,000

The minimum require-ment is a WOC time of less than 12 hours.

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Engineering and Planning

Evaluation of Cementing Job Proposal

Evaluation and quality control of the service company’s job plan, simulator runs, slurry design, and laboratory test results is necessary to ensure that the cement slurry design fits the planned operation.

Data Review and Verification

1. Check the accuracy of Subject, Field, Well and Rig entries. Well data include the following:

• hole and pipe sizes • hole and pipe weights

• annular, hole, and pipe volumes

Caution—Do not proceed unless these data are confirmed.

2. Review the BHST and BHCT; if any deviation or uncertainty exists, investigate further.

3. Review the Cement Slurry Formulation to verify that it matches the slur-ries tested in the laboratory.

4. Read the Density, Yield and Mix Water requirement.

• Mix Water—Use this value to calculate the volume of water needed for the job.

• Density—Mix the cement slurry to this value

• Yield—Use this value to calculate the number of “sacks” required for the job.

5. Review the Cement Job Simulation as follows: a. Check inputted values.

b. Review the following data output against the job plan. • pumping rates

• ECDs

• placement pressure at the pump • spacer contact time

c. Change planned pumping rates as necessary. 6. Review the centralization program, taking note of

• centralizer placement and type

• minimum standoff across zones of interest

Do not proceed until well data have been confirmed.

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Engineering and Planning

Review of Cement Job Simulation

Although gas flow may not be apparent at the surface, it may occur between zones, damaging the cement job and eventually leading to casing pressure at the surface. A cementing simulator program can be used to determine the gas flow potential for any primary cement job, and to identify possible solutions that are tailored to the severity of the possible gas flow.

Run the simulator to test equivalent circulating densities (ECD), flow regime of the different fluids, required rheological properties of the fluids, maximum pumping rates, centralizer standoff requirement, displacement efficiency, anticipated pumping pressures at surface, pressure to shear or bump plugs, BHCT, etc. Using this tool will aid in job design and will help identify any potential problems with the design.

Interpretation of “Pilot” Test Results and Laboratory

Reports

1. Check cement slurry formulation for the following information: • Cement type

• Additive types and concentrations • Water source and concentration

2. Check cement slurry “pilot” test results against specifications as listed in the following table.

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Engineering and Planning

Slurry Property Task Notes Density Check test value. — Thickening Time Check times and test

temperature.

Test temperature must be at BHCT.

Time must be within the specified range.

Use 70 Bc for liner and narrow clearance jobs. Use 100 Bc for surface and intermediate jobs. Attach strip chart for the

thickening time test.

—

Check time reported vs. times read from chart.

—

Fluid Loss Check value and test temperature.

Rheology Check PV, YP and test temperature.

PV and YP must be reported.

Test temperature must be at BHCT, 194F maximum. Compressive

Strength

Check the time for WOC (500-psi) and check 24-hr strength.

Test temperature must be at the requested value.

Free Water Check value and test temperature.

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Job Procedures

This section contains basic procedures for every step of a job, from prejob preparations to pumping and displacement. Throughout each phase, it is very important to monitor and record various measurements, times, and events. This information allows the job to be tracked as it is carried out, and is invalu-able in troubleshooting an unexpected problem.

Monitoring and Recording

Use the following checklist to ensure that all pertinent job data is captured at the appropriate time as each job is executed.

Prejob Preparations

• Loading of wiper plugs or darts • All volume calculations

• Circulation of hole till clean Pumping Operations

• Pressure testing

• Start and stop of each fluid pumped • Pumping rates for each fluid

• Any pumping rate changes • Any pressure changes • Volume of spacer pumped • Dropping any plug, dart or ball • Start of cement slurry mixing • Cement slurry density

• Mix water volume • Start of displacement • Surface pressures • Displacement rate • Landing of plugs

• Pressure to release liner wiper plugs • Pressure to bump top plug

• Reverse circulation • Total displacement • Job time

• Returns • Any shutdown

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Job Procedures

Prejob Preparations

Cement Design Verification

1. Verify that the following cement design and test conditions coincide with current well conditions.

a. BHCT and BHST

b. Thickening time and job time c. WOC time

2. Verify the following calculations. a. Volumes for all fluids to be pumped b. Hole and pipe volumes

c. Total displacement volume to bump plugs and correction factor as applicable

d. Pressure to bump plug

e. Volume to catch liner wiper plugs, and displacement volume from that point

3. Review the cement job simulator.

4. Review pumping rates for wash/spacer, cement slurry and displacement. 5. Review pumping pressures expected during the job.

6. Review ECD’s at shoe and zones of interest. 7. Review the returns expected during the job.

Equipment / Materials Verification

1. Check the bulk tanks for proper contents.

2. Confirm that all equipment (include a complete list) is on location and in good working condition.

3. Check operational features, ensure that the float backpressure valve is operational, and that the plugs are of the correct type and fit.

4. Check wiper plugs, the bottom plug (hollow), and the top plug (solid). 5. Witness the loading of plugs.

6. Confirm the delivery rates for water and mud.

7. Confirm what type of displacement fluid will be used and the parties responsible for routing and pumping downhole.

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Job Procedures

8. Confirm that all density devices have been calibrated properly with fresh water.

Wellbore Circulation

1. Clean and stabilize the wellbore by circulating during wiper trips, before and after logging.

2. Run the casing at a controlled rate, and circulate drilling fluid at intervals. If there is known potential for lost circulation, run the casing at less than 1 minute per stand.

3. Condition the drilling fluid until drilling fluid properties are optimized (PV < 15; YP < 10).

4. Move the pipe via reciprocation or rotation during conditioning.

5. Circulate the wellbore until clean, using a minimum of two bottoms-up. Total conditioning time is determined by drilling fluid properties and the circulatable hole volume.

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Job Procedures

Pumping Operations

Pressure Testing

1. Pump wash or spacer to the cement head.

2. If running two bottom plugs, load the first bottom plug into the casing at this time.

3. Connect (reconnect) the cement head. The bottom and top plugs should have already been loaded during prejob preparations.

4. Clear the rig floor and the area surrounding the lines. 5. Pressure-test the lines as follows:

a. Increase pressure to a predetermined level. b. Hold the pressure for 5 min.

c. Release the pressure.

Mixing and Pumping Cement

1. Drop the bottom plug (the first one, if using two).

2. Pump the wash or spacer. Standard pumping rates are 6 to 8 bbl/min. Caution—Never open the cement head once pumping has begun.

3. Drop the second bottom plug (if running two bottom plugs).

4. Start to mix and pump the cement slurry. The standard pump rate is 5 to 8 bbl/min, depending upon the specific job.

5. Measure the mix water for the cement slurry through the displacement tanks and record the measurement.

6. Control the density within 0.2 lb/gal accuracy throughout the job. 7. Check the cement slurry density with a pressurized balance to calibrate

the densitometer.

8. Confirm slurry density by monitoring the pressure (downhole) readings of the densitometer.

9. Continue to mix and pump cement.

Important—Never compromise slurry density to maintain the scheduled pump rate.

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Job Procedures

Caution—Near the end of the job, bulk delivery may decline. Never sacrifice density control to use up the cement. If the designed density cannot be main-tained, discontinue cement slurry mixing.

10.After the cement is pumped, drop the top plug.

11.Displace the top plug out of the cementing head with minimal down time. 12.Do not open the cementing head to drop the top plug.

13.Begin displacement.

Displacement

Measure the displacement volume with the cementing unit displacement tanks or rig pumps. DO NOT use a “barrel counter.”

1. Maximize displacement with a pump rate of 8 to 12 bbl/min. Limit the rate only if necessary to prevent excessive ECD’s.

2. Maximize the pump rate as spacer passes zones of interest.

3. Begin decreasing the pump rate as the final displacement volume nears. 4. Displace to bump the top plug at 1 to 2 bbl/min. Never overdisplace. 5. After displacement is completed and the plug has been bumped, relieve

surface pressure and check for flowback.

Important—Do not hold pressure inside the pipe unless operations will be compromised by flowback.

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Job Procedures

Shallow Water Flow Cementing

Consider the following standard shoe track, centralizer, and wiper plug requirements for use in shallow water flow cementing:

• a stab-in float shoe

• one joint with two bow-spring centralizers

• one bow-spring centralizer per joint to the drive pipe • one centralizer per joint between casing and casing

To cement casing in a shallow-water-flow formation, use the following proce-dure.

1. Drill the conductor hole section with MWD so that sand depths are known.

2. Set the conductor casing above potentially flowing sands.

3. Cement the conductor pipe, using centralizers, etc. to achieve complete coverage.

4. Drill with controlled drilling fluid.

5. Once the casing point is reached, pump out of hole with kill-weight mud that has low gel strength (i.e. yield point of 8 to 10 lbf/100 ft2, 10 ft, 10 in. and 30 in. gels flat and < 25 lbf/100 ft2).

6. After pulling out of hole before running casing, observe for flow. If flowing, increase the mud weight in the hole.

Caution—Conducting a cement job with the well in flowing condition will most likely result in channeling, causing the job to be unsuccessful.

7. Run the casing, maintaining kill-weight mud in the hole at all times. 8. Design a program to eliminate seawater in the drillpipe and casing below

the stinger.

9. Before running in hole, displace the drillpipe and casing below with the same mud weight as that in the hole.

10.Circulate in hole and fill the drillpipe with the same mud weight as that in the hole.

11.Pump the required spacer system weighted to a density between that of the mud in the hole and that of the lead cement slurry.

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Job Procedures

12.Run the designated cement system with a foamed lead slurry (1.0 ppg heavier than the drilling mud) and a non-foamed tail slurry.

13.Pump the cement and allow it to set to 500-psi compressive strength before drilling out.

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Job Procedures

Wait on Cement (WOC)

For operations, waiting on cement (WOC) is the waiting time required after cementing in order to safely remove well control equipment or to allow the well to be underbalanced.

For a cement slurry, WOC is the time necessary for the cement to solidify and attain a compressive strength of 500 psi. This is most effiiciently determined through laboratory testing with a UCA, which plots strength development vs. time.

To maximize the efficiency of WOC, adhere to the following guidelines. • Know the well conditions before, during, and after the cement job. • Know the WOC (500-psi time) for the cement slurries pumped. • Never allow the well to be underbalanced during WOC.

• Minimize WOC by using the correct cement systems that develop strength quickly after placement.

• WOC cannot be accurately determined from thickening time alone. • In some areas, regulations specify minimum WOC times that may exceed,

and thus supercede, these guidelines.

• During the WOC period, perform operations that can help minimize the time and cost of WOC, such as

• Pick up drillpipe for the next hole section. • Run any required surveys.

• Clean up the mud by circulating it over shakers.

• Rigup equipment that may be required for the next hole section.

Know the WOC (500-psi time) for the cement slurries pumped.

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Plug Cementing

Plug cementing is the process of placing a column of cement in casing or an openhole to isolate or “plug” a section of the wellbore. This best practice pro-vides important guidelines that must be considered when designing a plug job, as well as a detailed procedure for carrying out a plug cementing opera-tion to ensure proper placement of the plug and adequate zonal isolaopera-tion.

Engineering and Planning

Plan a plug job based on hole conditions to pull out of cement. Many methods are available and consideration should be given to prevention of contamina-tion, risk exposure, environmental spill considerations, etc. The well depth, the mud type, and many other factors will determine which procedure should be used.

Placement

Use a small workstring to balance cement plugs for optimal displacement. The length of the tail pipe must be at least equal to the plug length with tubing in place.

Tubing vs. Drillpipe

Run the tail pipe to the planned bottom of plug depth. Tubing diameters of 2 7/8 in. should be used in slim holes of 8 1/2 in. or less; 3 1/2-in. tubing should be used for larger hole sizes. Tubing is preferred over drillpipe in plug jobs because the displacement of the tubing reduces swabbing and reduces the weight of pipe to be pulled. For 17 ½-in. or larger open plugs, this is not criti-cal and thus, they can be set using drillpipe. Coupling OD’s of the tubing should be minimized. If no tubing is available, 3 ½-in. drillpipe may be used. If a stinger is to be run through open hole or in casing after a milling opera-tion, break circulation every 5 to 10 stands to prevent plugging of the stinger. Diverter Sub

A diverter sub can improve the success of cement plug setting by directing the flow and preventing the jetting of cement downhole. Use a distribution (diverter) tool to direct flow up the annulus, such as a bull plug with four to eight small (approximately 1-in.) horizontal side holes greater than the flow area of tailpipe and at 90-degree phasing. If a wiper plug catcher is used, place it below the holes.

Plug Length

Assume that the top and bottom 100 ft of cement will be contaminated with spacer.

Tubing diameters of 2 7/8 in. should be used in slim holes of 8 1/2 in. or less; 3 1/2-in. tubing should be used for larger hole sizes.

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Plug Cementing

If large quantities of cement are observed above the top of cement when cir-culating the well clean, channeling has likely occurred, and the area contami-nated by the spacer will be larger than normal. This will increase the risk for failing to tag the plug and/or for obtaining a pressure test.

Cement plugs set across perforations should be set from 100 ft below the per-forations to 200 feet above the perper-forations.

Recommended plug lengths are as follows:

• Plugs of 300 to 600 ft have been used for 8 ½-in. to 36-in. open holes for abandonment, suspension and sidetracking in wells that are less than 14,500 ft deep and have less than a 45° inclination.

• For recovery of oil-based and synthetic-based mud, 1,500-ft abandonment plugs have been set in 12 ¼-in. open holes with thickening times exceed-ing 10 hr.

• In 8 1/2-in. and smaller open holes, plugs of up to 800 ft have been set and successfully tagged to ensure a minimum volume criterion is met.

• Plugs in extended reach wells are special cases and where plug setting depth exceeds 14,500 feet and hole angle exceeds 45°, plug length should be 600 to 750 ft, with 300 ft of contamination allowance on top of the plug.

Caution—Minimize your risk by making sure plug lengths are adequate. Drilling out excess cement is normally far less expensive than setting a sec-ond balance plug to accomplish required objectives. No cement plug of less than 20 bbl should be set through drillpipe for a 6-in. or larger open hole. Caution—If there is a risk of lost circulation, do not place more than two plugs in a row without waiting the time required for the first plug to attain 500-psi compressive strength.

Cement Volumes

Whenever possible, use a caliper log to determine the cement volumes and to help determine where to set a plug. Setting a plug in a section of the hole that is near gauge will increase the chances for success.

If no caliper is available, refer to the following table for recommended per-centages of excess volume.

Minimize your risk by making sure plug lengths are adequate. Never use a cement plug of less than 20 bbl set through a drill-pipe for a 6-in. or larger open hole.

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Plug Cementing

Always consider the particular area and hole conditions such as sloughing shales or losses when determining the actual excess to be used.

Cement Slurry Design

Temperature

Make sure the BHST and BHCT are accurate for proper job design.

Select the temperature for your design on the basis of deviation, operation, and local experience.

Wherever hole angle exceeds 60°, perform a temperature simulation. In water depths exceeding 1,500 ft, predict cooling in the riser.

Allow some safety margin for slurry test temperatures; if no local expertise is available, allow a 10°F margin.

Slurry Properties

For kick-off plugs, the density of the slurry is important for rapid, high strength development.

• For Class G cement, use 16.2 to 16.5 ppg densities. • For Class H cement, use 17.0 to 17.2 ppg densities.

• Add a dispersant and/or retarder as needed to densify and to provide the required pump time.

Plug and abandonment plugs and squeeze plugs are generally designed at nor-mal density for the cement available, but may be adjusted for specific well conditions. Dispersants and retarders are the most common additives used. A fluid loss control additive may also be required for some open hole and squeeze operations.

Calculation of Volume Excess

Hole Size (in.) % Excess (Water-Based Mud) % Excess (Synthetic-Based Mud) 30 to 36 200 — 24 to 30 100 — 14 3/4 to 17 1/2 50 20 12 1/4 30 20 6 to 8 1/2 30 20

Make sure the BHST and BHCT are accurate for proper job design.

For Class G cement, use 16.2 to 16.5 ppg densities.

For Class H cement, use 17.0 to 17.2 ppg densities.

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Plug Cementing

Fluid loss is required in plugs set across permeable formations; a fluid loss less than 150 ml is adequate for abandonment / suspension plugs. However, squeeze slurries should have less than 75 ml.

Thickening Time

For all cement plugs that are to be spotted and balanced, the required thicken-ing time is based on the calculation:

40 Bc time (in the lab report) must be greater than or equal to job pump time + time to pull out of plug + 1 hr (safety factor). Calculated pump time is based on time cement is moving, and does not include static time.

The recommended pulling rate is 30 to 50 ft/min.

Spacers

Separate mud and cement with adequate spacer/wash. • For sea-water mud, pump water as a spacer/wash.

• For synthetic-based mud, pump a weighted chemical wash system or spacer system to displace mud and provide a water-wet surface for bond-ing.

Calculate the volumes of spacer/wash as follows.

• The volume of spacer/wash ahead of the cement should equal 500 ft of annular fill.

• The volume of spacer/wash behind the cement should be calculated to balance.

• Always calculate the loss in hydrostatic pressure ahead of a cement plug.

Cement Slurry Displacement

Use a cement unit to displace the cement slurry to ensure accurate control over displacement volume.

The displacement can be accurately determined with an indicator sub, usually positioned in the drillpipe above the balance point. The tool used will provide a positive indication of displacement volume when it makes contact with the plug catcher sub.

When an indicator sub is not used, a slight under-displacement, typically 1 to 3 bbl, is recommended in order to pull dry. For deep plugs, the average pipe ID should be determined to ensure a correct displacement volume.

40 Bc time (in the lab report) must be greater than or equal to job pump time + time to pull out of plug + 1 hr (safety factor).

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Plug Cementing

Mechanical Tools for Supporting Cement Plugs

Mechanical tools should be used only where necessary. Setting a reactive pill may be more economical and easier, if support is necessary. The simplest tool is a small sub run on the end of the tubing stinger that holds a short

“umbrella” like tool. When a ball is dropped, the umbrella extrudes and then springs open to an approximate 20-in.diameter. This tool can be run in open hole and casing. In casing, inflatable packers or mechanical bridge plugs set on wireline can be used.

Inflatable packers and mechanical bridge plugs are not suitable for use in open holes.

Waiting On Cement

Plugs should not be tagged until they have at least 1,000-psi compressive strength. A total of 1,500-psi compressive strength is required for pressure-testing the plug.

Kick-off plugs require a compressive strength of 3,000 psi. Deep kick-off plugs (placed at depths of 10,000 ft or more) across hard formations will require 4,000-psi compressive strength.

Compressive strength should be determined at a temperature mid-way between static temperature and the temperature used for designing the pump-ing time, unless more precise values are available.

Kick-off plugs require a compressive strength of 3,000 psi.

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Plug Cementing

Job Procedure

1. Make sure the stinger is run at least 300 feet below the plug-setting depth.

Note—In an openhole situation, consider jetting across the interval.

2. Pull back to plug-setting depth, condition the mud, and circulate the annu-lus clean a minimum of one bottoms-up while moving pipe.

3. Pump 500 ft (up to 50 bbl) of spacer/wash ahead of cement. As in primary cementing, the weight of the spacer/wash should be halfway between mud weight and cement weight.

4. Pump cement.

a. Check the density using a pressurized mud balance. b. Control the mixing rate at 2 to 4 bbl/min.

c. If the cement is mixed with a jet mixer, dump the first quantities of cement overboard until a consistent slurry is obtained.

d. If a batch mixer is used, disregard Step 4c.

5. Pump a volume of spacer/wash behind the cement to balance the spacer ahead of cement. Rotate pipe (approximately 20 rpm) to improve cement displacement into the annulus in deviated wells.

6. Displace at a maximum rate (limited by ECD) to improve gelled mud removal; then reduce the displacement rate according to the following guidelines:

• For hole sizes less than 12 1/4-in, pump at 2 bbl/min for the last 20 bbl.

• For hole sizes greater than 12 1/4-in, pump at 3 bbl/min for the last 40 bbl.

7. Under-displace by 1 to 3 bbl, excluding the volume of surface lines, unless using a latchdown sub, to ensure the plug is not contaminated and that the pipe pulls dry.

Note—For ultradeep jobs, a ball catcher sub and wiper plugs may be required to effectively verify displacement.

8. Pull out of the plug at a controlled rate (approximately 25 stands/hour) to prevent swabbing and contamination.

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Plug Cementing

Caution—Minimize any unnecessary time from shutdown to pullout. The thickening time estimate is based on moving cement; once the cement is static, this time allowance is reduced.

Note—Step 9 below does not pertain to intermediate plugs set in series. 9. If ECD’s allow reverse circulation, pull back to approximately 500 ft

above the top of any cement plug that is not to be tagged, otherwise go to the TOC; then, reverse circulate clean.

Caution—Reverse circulation can only take place if the ECD would not induce losses.

If reverse circulation is not possible due to losses or differential sticking, perform the following steps before POOH:

a. Flush the pipe clean.

b. Displace 150% of the pipe’s contents at maximum rate.

c. Drop a dart or pump 50 bbl of 50 pp. Nutplug in active mud to clean pipe of cement rings. In the latter case, the size of openings in diverter tool needs to be considered.

10.When going in hole to tag a cement plug, start washing down and rotating pipe at the previous depth of last bottoms-up circulation or 500 to 1,000 ft above the calculated top of cement.

Where a plug is being tagged with a kick-off assembly, use minimum flow rates.

Caution—Do not run back into a cement plug with the stinger until the cement has set. When the plug has been tagged, do not run back into the cement without circulation.

Minimize any unnec-essary time from shutdown to pullout. The thickening time estimate is based on moving cement. Once the cement is static, this time allowance is reduced.

Reverse circulation can only take place if the ECD would not induce losses.

Do not run back into a cement plug with the stinger until the cement has set. When the plug has been tagged, do not run back into the cement without circulation.

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Squeeze Cementing

Squeeze cementing is the process of placing cement into a confined area with hydraulic pressure. Often this cementing process does not attempt to

“squeeze” or dehydrate the slurry at all but to place high quality, noncontami-nated cement in the proper location to provide isolation or achieve other objectives.

Engineering and Planning

Before a squeeze cement job is designed, it is important to identify the objec-tives to be met and to perform a risk analysis.

Some of the more common objectives include: • Repair a failed primary cement job.

• Add to the height of the cement column in place to produce upper zones. • Eliminate water from above, below, or within the hydrocarbon zone. • Reduce the producing gas:oil ratio.

• Repair a casing leak.

• Seal the annulus of a liner top or casing shoe.

• Plug all, or part, of one or more zones in a multi-zone injector or produc-tion well.

A risk analysis should include: • Well control considerations.

• Pore, fracture and planned squeeze pressures. • Work-string and displacement accuracies.

• U-tube effect, hydrostatic pressure, and location of cement. • Casing condition, especially for old wells.

• Ability to contend with unexpected events. • Worst-case pressures for circulating out.

Placement

There are two basic squeezing techniques: the Bradenhead squeeze and the Bull Head squeeze.